Direct Testimony Mr. Matthew A. Troxle Before the Public ... · 9 Schedule 2. The more detailed...

Direct Testimony Mr. Matthew A. Troxle

Before the Public Utilities Commission of The State of Minnesota

In the Matter of the Application of CenterPoint Energy Resources Corp., d/b/a

CenterPoint Energy Minnesota Gas For Authority to Increase Rates for Natural Gas Utility

Service in Minnesota

Docket No. G-008/GR-15-424 Exhibit______(MAT-D)

Class Cost of Service

August 3, 2015

MR. MATTHEW A. TROXLE Docket No. G-008/GR-15-424

TABLE OF CONTENTS Page I. Introduction .……………………………………………………………………………1 II. Class Cost of Service ………………………………………………………………...2

A. Results ……………………..……..….…………………………………….…..….5

B. Allocation of Income Tax …………………………………………………………6

C. Fixed Cost Recovery ……..…………………..……..….………………………..7 III. Functionalization / Classification / Allocation Methodology ………………………11

A. Process …………………………………………………………………………….11

B. ICCC Customers ………………………………………………………………….45

C. Minimum System Study ………………………………………………………….51 IV. Summary and Conclusion……………………………………………..……………..55

Mr. Matthew A. Troxle Direct Testimony Class Cost of Service Docket No. G-008/GR-15-424

1

I. INTRODUCTION 1

Q. Please state your name, business address, and position with CenterPoint Energy 2

Service Company LLC, (“CenterPoint Energy”). 3

A. My name is Matthew A. Troxle. I am the Director of Rates, Rates & Regulatory 4

Research for CenterPoint Energy at 1111 Louisiana Street, Houston, Texas 5

77002. 6

Q. What are your present responsibilities? 7

A. My duties include directing the development and implementation of strategy 8

around cost of service, revenue requirements, cost allocation, rate design, and 9

tariffs for delivery rates in many jurisdictions across six different states. I also 10

coordinate with many departments in conjunction with the development and 11

implementation of risk mitigation strategies for changes in revenues and costs. 12

This includes review, analysis, and participation in the formulation of law, rules 13

and policy at the state and federal level. In this proceeding, I have overall 14

responsibility for presenting CenterPoint Energy’s Class Cost of Service study. 15

Q. Describe your educational background, as well as your business and 16

professional experience. 17

A. Exhibit______(MAT-D), Schedule 1, is a summary of my educational and 18

professional experience. 19

Q. What is the purpose of your testimony? 20


2

A. The main objective of my testimony is to present and sponsor the Cost Allocation 1

and Rate Design (CARD) model. I will also describe the allocation factors and 2

methodologies used in the CARD model. 3

II. CLASS COST OF SERVICE 4

Q. Minnesota Rule 7825.4300, subp. C. requires a class cost of service study 5

(CCOSS) by customer class in each rate filing. Have you included a CCOSS in 6

your testimony, exhibits, and workpapers? 7

A. Yes. The results of the CCOSS are summarized in Exhibit _____(MAT-D), 8

Schedule 2. The more detailed cost allocation model (the CARD model) is found 9

in Workpaper 1, Workpaper 6, Workpaper 7, and Workpaper 8. A detailed 10

technical appendix is included in my direct testimony as well, which explains the 11

allocation method used for each FERC account to assign costs to rate classes. 12

Q. Did CenterPoint Energy use a similar cost causation model in this filing, as was 13

used in its 2005, 2008, and 2013 rate request proceeding? 14

A. Yes. The Company used the same model, the Cost Allocation and Rate Design 15

(CARD) model, revised per Commission Order. All inputs have been updated to 16

reflect the data representative of the new base year and test year. The model 17

uses cost causation, or causality, as the controlling element of the cost 18

classification and cost allocation. As a result, this testimony, schedules, exhibits, 19

and the CARD model itself are essentially the same as in previous CenterPoint 20

Energy rate cases before the Commission. 21


3

Q. Please describe the general ratemaking process once the cost of service is 1

established. 2

A. The ratemaking process for translating the cost of service into rates involves 3

three steps: 1) cost classification; 2) cost allocation; and 3) rate design. Cost 4

classification is the process of determining the nature of costs, i.e., whether costs 5

are customer-related, demand-related, or usage-related. Cost allocation is the 6

subsequent process of attributing those costs to specific customer classes based 7

upon the appropriate allocation methods and factors. I have used cost 8

classification and cost allocation methodologies that are commonly used 9

throughout the industry, and were used in the Company’s previous general rate 10

filing in 2013, Docket No. G-008/GR-13-316. 11

Q. Did the Commission order the Company to file multiple CARD models in Docket 12

No. G-008/GR-13-316? 13

A. Yes. CenterPoint Energy was ordered in its next rate case filing, to run multiple 14

iterations of the minimum system study in the CARD model, to reflect the 15

Company’s recommended 2-inch pipe, as well as 1-inch pipe, and a zero-inch 16

pipe.1 17

Q. Do the provided CARD models comply with the Commission’s previous Order? 18

A. Yes, they do. The Company’s recommended 2-inch minimum system is reflected 19

in Workpaper 1, while the 1-inch and zero-inch minimum systems are reflected in 20

Workpapers 6 and 7, respectively. 21

1 June 9, 2014, Findings of Fact, Conclusions of Law, and Order. Docket G-008/GR-13-316, No. 22.


4

Q. Have you filed an additional CARD model? 1

A. Yes. Workpaper 8 is an alternate version of the CARD model that reflects the 2-2

inch minimum system and alters some allocation factors based upon the 3

Commission’s final determinations applicable to the Company’s previous rate 4

case. 5

6

Q. Do all of CenterPoint Energy’s filed CARD models accurately reflect the 7

company’s class cost of service as required by Minnesota law? 8

A. Yes, they do. The models are compliant with Minnesota Statute and Rule, and 9

each reflects the set of assumptions being modeled, and in general the models 10

are fully linked and fully functional, meaning that the input data “flows” through 11

the model, and accurately reflects the company’s class cost of service, as filed. 12

Q. Which CARD model do you recommend for adoption in this proceeding? 13

A. I recommend adoption of the first CARD model, presented in Workpaper 1, which 14

reflects a 2-inch minimum system study. 15

Q. If the Commission ultimately decides to change any of the inputs in any of the 16

CARD models, does the model become invalid? 17

A. No, it does not. No confidence should be lost in the CARD model itself if the 18

Commission decides a particular contested issue in a fashion contrary to what 19

has been proposed by the Company in the CARD models. However, the 20

supplied and recommended CARD model is illustrative of the Company’s filed 21


5

case. Therefore, if the Commission elects to change the inputs to the CARD 1

model, the outputs will need to change accordingly. This is not a deficiency that 2

should cause a lack of confidence in the CARD model or its results. The fact that 3

inputs “flow” through the CARD model and change the outputs, actually proves 4

that the model is fully linked, fully functional, and that it works as intended. 5

Q. If outputs can change with any Commission decision that impacts the CARD 6

model’s inputs, how should the Commission reflect changed inputs and outputs? 7

A. CenterPoint Energy is willing to file a “number run” or a “compliance run” to 8

reflect the impacts of the Commission’s decisions, whether the request be for 9

illustrative impact purposes before a final decision is made on an issue, or if the 10

Commission would like the numbers after a decision on a particular issue so that 11

the final numbers can be included in the Commission’ Final Order. This way, the 12

“flow-through” impacts of any changes will be known on the ultimate rate design 13

and the Commission will not be locked into the status-quo because of a lack of 14

up-to-date information. With updated “number runs” the Commission will know 15

what new revenue requirements translate into for rate design purposes. 16

II.A. RESULTS 17

Q. Please discuss the results of the class cost of service study. 18

A. The class cost of service study shows an overall revenue deficiency to the 19

Company of -$54,105,336.2 20

2 Direct Testimony Matthew Troxle, Exhibit (MAT-WP) Workpaper 1, page 4, line 11.


6

Q. How is the overall revenue deficiency attributed to the individual customer 1

classes? 2

A. I have summarized the class revenue deficiency in the chart below. These 3

amounts can be found on page 4, line 11 of the Workpaper 1 CARD Model. 4

Total -$54,105,336 Residential -$60,936,228 Commercial/Industrial A -$ 6,156,106 Commercial/Industrial B -$ 2,629,033 Commercial/Industrial C $ 6,220,649 Large Firm Sales + Transportation $ 2,497,220 Small Dual Fuel-A $ 4,779,181 Small Dual Fuel-B $ 2,954,391 Large Dual Fuel -$1,023,866 Small Dual Fuel-A-Transportation $1,142,610 Small Dual Fuel-B-Transportation $1,082,332 Large Dual Fuel-Transportation -$2,036,488

II.B. ALLOCATION OF INCOME TAX 5

Q. Please discuss the allocation of income taxes. 6

A. In the previous rate case, the Company showed alternative methodologies to 7

allocate income taxes, with the Company’s recommended proposal being to base 8

the allocation of income taxes upon a taxable income allocator.3 For this rate 9

case, the company has allocated test year income taxes in the CARD models 10

consistent with this methodology, which was accepted by the Commission in the 11

Final Order in Docket No. G-008/GR-13-316.4 12

3 Docket No. G-008/GR-13-316, Direct Testimony of Matthew Troxle, August 1, 2013, pages 7-8. 4 June 9, 2014, Findings of Fact, Conclusions of Law, and Order. Docket G-008/GR-13-316, XVIII. Class Cost of Service Study, B.4. Commission Action, page 35.


7

Q. Has the Minnesota Department of Commerce endorsed this income tax 1

allocation methodology? 2

A. Yes. In the prior CenterPoint Energy rate case, G-008/GR-13-316, Department 3

of Commerce witness Holly Lahd agreed that the Company’s proposed 4

methodology was compliant with the Commission’s intent on income tax 5

allocation methodology.5 6

II.C. FIXED COST RECOVERY 7

Q. Please discuss what you mean by the term “fixed cost” in the context of natural 8

gas distribution. 9

A. Capital intensive activities, such as natural gas distribution, are substantially and 10

inextricably linked to the physical dimensions of the installed distribution system 11

facilities. The assets required to achieve natural gas distribution are in the form 12

of pipe buried within rights-of-way and surface equipment for pressure regulation 13

and measurement at fixed locations. The very nature of these assets is more 14

permanent than temporary, rarely mobile, and not based upon variable gas 15

volumes. Because of the permanency of these assets, their existence is based 16

on obligations or commitments to provide services. These services certainly 17

involve consumption, but their primary significance is the commitment or standing 18

utility obligation to serve, whether actual consumption during a particular time 19

period occurs or not. Thus, tracing cost causation for these capital-related fixed 20

costs requires an understanding of how the installed distribution facilities are 21

5 Docket No. G-008/GR-13-316, Direct Testimony of Holly Lahd, November 26, 2013, page 12.


8

committed to serve as well as the consumption patterns associated with the 1

facilities. 2

Non-capital-related fixed costs can include labor, materials and supplies 3

consumed, and other indirect costs that are consumed but not capitalized are 4

also linked to the standing obligation to serve from installed distribution facilities. 5

This is because these costs are required to maintain, repair and ensure the 6

ongoing safety, reliability and level of installed distribution facilities. The ongoing 7

maintenance of safe, reliable, distribution facilities is as much a requirement of 8

the obligation to serve as the original installation of the facilities. 9

In summary, fixed costs vary with the passage of time, not throughput. 10

Additionally, fixed costs are determined by the physical dimensions of the 11

distribution network necessary to meet the utility’s obligation to provide safe and 12

reliable service to its customers. 13

Q. You indicated that fixed costs can be capital-related and include return on, and 14

of, capital. Can some capital-related costs be variable as well as fixed? 15

A. Not in this case. In general, however, a capital-related cost can vary with units of 16

throughput. This occurs if the cost is linked with throughput as opposed to the 17

passage of time. For example, depreciation charges, which represent the return 18

of capital, are usually taken in equal periodic amounts based on a specific time 19

schedule. Thus, depreciation is usually a fixed cost related to the passage of 20

time. However, depreciation charges can be based on “units-of-production” that 21

generate depreciation charges based on the throughput associated with the 22

underlying asset. Depreciation based on units-of-production is only applicable to 23


9

assets with useful lives (physical or economic) measured in terms of the units of 1

product or service that can be ultimately provided. There are no capital-related 2

costs that are variable in nature in this case since none of the depreciation 3

charges are tied to units-of-production. 4

In general capital expenditures and the associated investments on natural gas 5

distribution systems are related to physical assets that have fixed locations and 6

are not mobile. As such, the associated capital cost and the related investment 7

are more or less permanent. Additionally, the costs associated with distribution 8

assets are incurred with the passage of time, not with variations in throughput. 9

Return on capital, both debt and equity-related, is tied to time schedules such as 10

interest payments, sinking fund requirements and the payment of dividends. The 11

level of the cost of capital can fluctuate based on variations in the financial 12

markets. This change in the cost of invested capital does not, however, mean 13

that the level of original investment somehow suddenly becomes “variable” as 14

that term is used in the rate determination process. The absolute levels of fixed 15

costs are not necessarily “static” because the prices of fixed costs can change. 16

Such price changes, however, should not be confused with costs that vary based 17

upon throughput. 18

Q. You indicated that fixed costs can be non-capital-related and include labor, 19

materials and supplies consumed, and other indirect costs that are consumed but 20

not capitalized. Can non-capital-related costs be “fixed” during one time period 21

but “variable” over a different or extended time period? 22


10

A. Perhaps, but it is not likely. Changes in non-capital-related fixed costs on natural 1

gas distribution systems can be traced almost exclusively to factors other than 2

variations in throughput. The level of fixed expenses can vary over time because 3

of changes in productivity, changes in technology, changes in the general level of 4

price inflation, changes in the prices of particular goods and services, and 5

changes in governmental regulation such as reporting requirements or other 6

factors external to a regulated utility. Whenever such factors serve to increase or 7

decrease the level of fixed-cost-related activities, there is the possibility that 8

changes in throughput can occur at the same time and in the same direction. 9

When this occurs, it can serve to create the illusion that there is some correlation 10

between throughput and fixed costs. However, I believe that observed 11

similarities between changes in the levels of fixed costs and throughput levels on 12

natural gas distribution systems are more often than not a matter of coincidence 13

rather than of causation. 14

Q. Does the CARD model show the appropriate level of customer cost recovery per 15

the information filed in this rate case? 16

A. Yes. Please see Workpaper 1, page 5, line 8 for the revenue requirement 17

properly associated with fixed costs. 18

Q. How does this level of revenue requirement translate into the customer charge 19

bill component? 20

A. Workpaper 1, page 5, line 10 shows the customer charges that are derived from 21

the level of revenue requirement associated with customer costs. 22


11

Q. Is the Company recommending these levels of customer charges? 1

A. No. The Company’s recommended customer charges are shown on Workpaper 2

1, page 6, line 16, and deviate from the cost of service revenue requirements 3

associated with customer costs. This is discussed in more detail in the Direct 4

Testimony of Company Witness Mr. Burl Drews. 5

III. FUNCTIONALIZATION / CLASSIFICATION / ALLOCATION METHODOLOGY 6

III.A. PROCESS 7

Q. Please give a brief description of how the CARD model assigns costs. 8

A. In the CARD model, costs are first functionalized by the Uniform System of 9

Accounts, as provided by the Federal Energy Regulatory Commission (FERC). 10

Once in the particular FERC Accounts, the costs are classified as either: 11

customer, capacity (demand), or commodity (usage) related costs, depending on 12

how they are incurred. Finally, the classified costs are allocated to customer 13

classes by the proportional contribution to the cost for each class. 14

The customer related costs traditionally represent certain fixed costs that each 15

customer should bear whether any gas is consumed or not. The costs are 16

considered “fixed” because the utility incurs the expense on behalf of the 17

customer even if there is no usage and the associated cost does not depend 18

upon the amount of gas the customer consumes. These costs vary depending 19

on the number or customers instead of the quantity of gas delivered to the 20

customers. 21


12

The capacity related costs traditionally represent the capital costs associated 1

with the use of the transmission and distribution system. These costs are 2

considered “fixed” because the pipes are built to reliably handle a maximum 3

system requirement level of demand from the customers, at any given instant. 4

These costs vary depending on the quantity and size of the pipes and equipment. 5

However, once the investment is made and the pipes are constructed, the costs 6

incurred by the utility do not vary with the amount of gas that flows through the 7

pipes or with the number of customers. 8

The commodity (usage) related costs traditionally represent the energy use costs 9

of the system. These costs are considered “variable” as they change based 10

upon the gas throughput rather than system demand or number of customers. 11

Q. Did the Order in Docket G-008/GR-13-316 place any requirements on 12

CenterPoint Energy in regard to describing the allocation methods used? 13

A. Yes. The Order states that in its next rate case, the Company shall include an 14

explanatory filing identifying and describing each allocation method used in the 15

class cost of service study and detail the reasons for concluding that each 16

allocation method is appropriate and superior to other allocation methods 17

considered by the Company.6 18

Q. Have you identified and described each allocation method used in the class cost 19

of service study? 20

6 June 9, 2014, Findings of Fact, Conclusions of Law, and Order. Docket G-008/GR-13-316, No. 23.


13

A. Yes. The allocation methods are identified in the CARD model itself. 1

Additionally, I have attached Workpaper 2 that discusses the identified 2

methodologies. 3

Q. Have you detailed the reasons for concluding that each method is appropriate 4

and superior to other methods considered by the Company? 5

A. Yes. In Workpaper 2, I have detailed why each identified method was 6

appropriately chosen for use. It must be noted that CenterPoint Energy does not 7

target any particular allocation outcomes in the CARD Model and then fashion 8

the case to try and achieve those outcomes. Thus, in identifying allocation 9

methodologies the process starts and ends with the methodology that is 10

theoretically correct for that FERC Account, utilizing as guides the NARUC Gas 11

Distribution Rate Design Manual, CenterPoint Energy’s specific system 12

requirement, its experience, and its engineering and operating characteristics. In 13

Workpaper 2, I have discussed the selected allocation methodologies and their 14

appropriateness and thus why they were selected. The question of why the 15

selected methodology is superior to others is slightly more problematic. 16

Q. Please address the problematic nature of attempting to describe why one 17

allocation method is superior to another. 18

A. Use of the word “superior” is subjective in that what customers in one customer 19

class view as superior may not be what customers in another customer class 20

view as superior. Thus, there will always be room for disagreement on what is 21

“superior” which is the reason why disagreements in rate cases are litigated. 22


14

However, from the Company’s point of view, as it is not representing any 1

particular set of customers, the theoretically correct allocation methodology is 2

superior to any other potential methodologies simply because it is theoretically 3

correct, not because of any specific outcome. Workpaper 2 discusses why any 4

particular allocation methodology is appropriate (and thus selected), thereby also 5

illustrating why the other potential allocation methodologies are inappropriate. In 6

my opinion this also indicates that if the other methodologies are inappropriate, 7

then the selected allocation methodology must be the “superior” choice. 8

However, other parties to this case may disagree and believe that a different 9

allocation methodology will give them a “superior” result for their represented 10

constituents. 11

Q. Have you prepared a technical appendix that discusses cost allocation, plant 12

functionalization, and cost classification? 13

A. Yes, below is a detailed technical appendix. 14

TECHNICAL APPENDIX – COST ALLOCATION AND RATE DESIGN – PLANT 15

FUNCTIONALIZATION AND COST CLASSIFICATION 16

Q. Please discuss CenterPoint Energy’s gas plant related to the central distribution 17

function. 18

A. The first gas plant account dedicated to the central distribution function, as 19

classified on Exhibit , (MAT-WP), Workpaper 1, (the CARD model), Page 7, is 20

Distribution Mains (“Mains”), recorded in Account No. 376, which is the cost of 21


15

installed distribution system mains. Distribution system mains are interconnected 1

to form distribution networks. Distribution networks connect the outlet side of city 2

gate stations to the inlet side of individual customer service lines. These 3

distribution networks are used in common by all customer classes. 4

This investment is caused by the requirement to (a) install facilities that connect 5

all customers to the common distribution network; and (b) install facilities with 6

sufficient capacity to meet the demands of all customers. For classification 7

purposes, this account balance is subdivided into (a) the portion of total costs 8

incurred to connect the central distribution network to the downstream transfer 9

points; and (b) the portion of total costs incurred to achieve the collective 10

capacity requirements of the central distribution network. 11

The connection cost of the central distribution network is isolated based on the 12

cost required to reach all individual customer service lines with the minimum 13

practical gas main size of 2 inches. This level of cost is referred to as the 14

“minimum system.” The cost related to the capacity of the distribution networks 15

is then defined as all costs in excess of the minimum system costs. 16

The total pro-forma cost of distribution mains is allocated based on the minimum 17

system analysis discussed in detail in the main body of this testimony. 18

Q. How did you select the “minimum practical size” as being 2-inch in terms of pipe 19

size? 20

A. The selection of 2-inch pipe is based on two characteristics or constraints. 21

These two constraints, taken together, are required to achieve the overall 22

purpose of the exercise, which is to isolate that portion of the original costs 23


16

recorded in the Mains account that can be reasonably attributed to connecting 1

the points of receipt into the system to points of transfer to the downstream 2

customer installations. 3

The first constraint on the pipe-size selection is the “absence” of capacity. 4

Specifically, the minimum main size should reflect the least amount of theoretical 5

capacity subject to the second constraint. 6

The second constraint on the pipe-size selection is the presence within the Mains 7

account at a level great enough to allow it to be representative of the utility’s 8

distribution system or network. This constraint is required by the fact that the 9

original costs to be apportioned have been accumulated over many years of 10

construction activity occurring under a variety of physical conditions and 11

economic circumstances. Therefore, the Mains account contains a multitude of 12

unit cost levels for each of the various pipe sizes and vintages. The Distribution 13

Mains account in this case, for example, has some installations that date back to 14

the late 1800’s as well as ongoing additions through 2015. Some of these mains 15

have been installed in underdeveloped pastureland while others have been 16

installed under existing streets and highways. Some of these mains were 17

installed in soil while other required trenching into bedrock. Additionally, the over 18

100-year construction period encompasses numerous business cycles. Thus, 19

the pipe size used for the minimum system analysis should have a sufficient 20

“footprint” within the Mains account to reflect original installation costs under a 21

variety of physical conditions and economic circumstances throughout the 100-22

year time period. 23


17

In this case, the 2-inch pipe category represents over one-half (52.98%) of the 1

Mains account in terms of linear footage and approximately one-fourth (25.71%) 2

of the Mains account in terms of cost. Thus, the footprint of the 2-inch pipe 3

captures a “variety of conditions and economic circumstances throughout the 4

100-year time period” peculiar to the Mains account.7 5

Q. Doesn’t the 2-inch minimum system encompass some level of capacity? 6

A. Essentially, no. While the 2-inch minimum system theoretically contains “some” 7

capacity it is neither significant nor readily determinable. In fact, capacity varies 8

dramatically based on a number of variables. Those variables include, for 9

example (1) flow rate of gas at base conditions; (2) base temperature; (3) base 10

pressure; (4) initial pressure; (5) final pressure; (6) specific gravity of the gas; (7) 11

flowing temperature; (8) length of line; (9) internal diameter of pipe, and (10) the 12

specific grid configuration. 13

Additionally, the mains in question are part of a network or grid, which has bends, 14

corners, and intersections, and has gas introduced and withdrawn at multiple 15

points. These mains are not simply connections between two discreet points. 16

Therefore, the level of capacity for any particular main size can only be 17

determined with the use of a capacity model (such as a “Stoner” or “SynerGee” 18

Model). Even then, determining the specific level of capacity using a capacity 19

model requires a separate calculation for each set of assumed operating 20

conditions and loads. 21

7 In contrast, 1 ½ -inch pipe, which is the next smaller size represents less than 1% (one percent) of the Mains account in terms of both linear footage and cost.


18

Q. Can you give examples that quantify the level of capacity in a 2-inch minimum 1

system as deployed in a real world application? 2

A. Yes, provided below are capacity estimates to illustrate capacity relationships. 3

These capacity estimates are example residential subdivisions to be provided 4

distribution service through gas mains under four configurations. These capacity 5

estimates were confirmed as reasonable by Company engineers and do not 6

represent any particular Minnesota subdivisions: 7

1. The actual piping solution that was determined with SynerGee 8

modeling techniques using the Weymouth engineering Equation; 9

2. A configuration using only 4-inch pipe, which is another pipe size 10

that occurs with a frequency above 10% within the CenterPoint 11

Energy system; 12

3. A configuration using only 2-inch pipe, which is the basis 13

designation for the “minimum system” based on its significant 14

footprint in the CenterPoint Energy system; and, 15

4. A configuration based on 1 ¼ -inch pipe, which represents the only 16

pipe size smaller than 2-inch of any significance in CenterPoint 17

Energy’s system. 18

The results of the three different residential applications are summarized in the 19

table below: 20

Relative Capacity of Various Piping Configurations - Actual Residential Applications 1 SUBDIVISION 1 2 Total Mains Required - Linear Feet 61,030

3 Average Linear Feet of Main per location 58


19

4 Maximum Hourly Demand per Location 75 Cfh 5 Total Locations Connected 1,047 6 Actual 4" 2" 1 1/4" 7 Number of Locations Actually Served 1,047 665 119 43

8 Actual Piping solution - 5,000 ft. of 6" plastic, 7,045 ft. of 4" plastic, and 44,905 ft. of 2" plastic, and 4,154 of 1.25" plastic. 100% 64% 11% 4%

9 Maximum Load per House 8.5 10 SUBDIVISION 2 11 Total Mains Required - Linear Feet 234,787

12 Average Linear Feet of Main per location 90 13 Maximum Hourly Demand per Location 60 Cfh 14 Total Locations Connected 2,600 15 Actual 4" 2" 1 1/4" 16 Number of Locations Actually Served 2,600 589 107 37

17 Actual Piping solution - 11,814 ft. of 8" steel, 7,084 ft. of 6" steel, 16,056 ft. of 4" plastic, 1,199 ft. of 3" plastic, and 191,171 ft. of 2" plastic. 100% 23% 4% 1%

18 Maximum Load per House 2.5 19 SUBDIVISION 3 20 Total Mains Required - Linear Feet 239,137

21 Average Linear Feet of Main per location 68 22 Maximum Hourly Demand per Location 80 Cfh 23 Total Locations Connected 3,520 24 Actual 4" 2" 1 1/4" 25 Number of Locations Actually Served 3,520 1,082 201 67

26 Actual Piping solution - 7,264 ft. of 12" steel, 14,043 ft. of 6" plastic, 27,985 ft. of 4" plastic, and 189,845 of 2" plastic. 100% 31% 6% 2%

27 Maximum Load per House 4.6 In this set of three real-world applications, none of the piping configurations (1 ¼ 1

-inch, 2-inch, or 4-inch) was adequate to serve these subdivisions even though 2

they were limited to residential customers. In fact, the 2-inch (minimum system) 3

configuration could only provide the required pressure to 119 out of 1,047 4

locations (11%), 107 out of 2,600 locations (4%), and 201 out of 3,520 locations 5

(6%) in subdivisions one, two, and three, respectively. In the actual design and 6

operation of natural gas distribution systems, piping solutions are subject to a 7

single standard, which is either “pass” or “fail.” This is because one cannot 8

attach more load to the distribution grid than it will handle without the risk of an 9


20

outage to the entire grid. Simply put, these three “minimum system” piping 1

configurations “failed completely.” 2

The actual piping solution for these three applications involved a mix of pipe 3

sizes and pressures. Additionally, these piping solutions serve to demonstrate, 4

by actual example, that larger diameter pipes are used to feed smaller diameter 5

pipes to serve large numbers of small customers. Thus, any notion that large 6

pipes are dedicated exclusively to serve large customers can be easily 7

dismissed. These results also demonstrate that the capacity of 2-inch pipe, at 8

standard operating pressures, over representative distances, is almost non-9

existent. 10

Thus, I have concluded that: (1) the 2-inch system is the smallest practical size 11

of this distribution system; and (2) the 2-inch minimum system contains the same 12

level of capacity for each and every customer. Therefore, the level of capacity 13

implicit in the minimum system is legitimately allocable on a customer basis. 14

These results are the same as presented by CenterPoint Energy in its previous 15

rate case before the Commission as the characteristics of the distribution mains 16

system are largely unchanged. 17

Q. Is there measurable overlap between the capacity implicit in the minimum 18

system, which is allocated on a customer basis, and the remaining capacity, 19

which is allocated on a design-day basis? 20

A. Whether there is measurable “overlap” depends on the degree of sophistication 21

included in the selection of the peak-related allocation factor. This is because 22

“capacity” is an instantaneous event. This fact is reflected in the residential 23


21

subdivision studies (discussed above) that focus on consumption in terms of 1

cubic feet per hour (“CFH”). The closer the peak-related allocation factor comes 2

to measuring the relative capacity requirement for each customer class on an 3

instantaneous basis the higher the degree of potential overlap between the 4

capacity contained in the minimum system and the capacity deemed as excess 5

to the minimum system. 6

In this particular rate application, the peak related allocation factor is based on 7

design-day weather conditions. Use of the design-day peak allocation factor is 8

an attempt to fully reflect the short-interval maximum demand of each customer 9

class.8 Therefore, the use of the design-day peak-related allocation factor 10

increases the degree of potential overlap as compared with a less sophisticated 11

peak-related allocation factor such as “average day during a winter-month.”9 12

Q. Have you accounted for this potential overlap? 13

A. Yes, the potential overlap has been accounted for with an adjustment to the 14

peak-related allocation factor. The calculation uses as a starting point the 15

design-day demand for firm services by customer class and the average annual 16

daily use for interruptible services, also by customer class. I adjusted this 17

relative demand level for each customer class to eliminate the maximum level of 18

capacity that I believe could be reasonably associated with the minimum system. 19

Specifically, I subtracted 120 cubic feet per day, for each customer, from the 20 8 It does not fully reflect the actual instantaneous burst rates of demand of each customer class, which would require at least hourly if not continuous load measurement. 9 Use of the average day during a winter month as a peak-related cost allocation factor significantly understates the peak responsibility of weather sensitive (residential and small commercial) classes relative to non-weather sensitive classes (large commercial and industrial) because the method makes no attempt to measure daily load variations within the winter month used.


22

otherwise applicable design-day for each customer class. This calculation 1

assumes that: (a) the capacity contained within the minimum 2-inch system is 2

equal to 5 cubic feet per hour for each customer; and (b) each customer uses the 3

5 cubic feet per hour of capacity on a continuous, 24-hour basis during the 4

“design-day.” In other words, it assumes that the minimum-system related 5

capacity is used all the time and that only “excess” capacity is “rested” during the 6

course of the design-day with its severe weather conditions. 7

Q. How did you determine the 5 cubic foot per hour figure used as an adjustment? 8

A. That figure is based on the results of the subdivision studies discussed earlier, as 9

well as the physical parameters of CenterPoint Energy facilities. Specifically, the 10

residential subdivision studies indicated minimum-system capacity levels (for a 2-11

inch system) of 8.5 CFH, 4.6 CFH, and 2.5 CFH in subdivisions where services 12

were 58 feet apart, 68 feet apart, and 90 feet apart respectively.10 CenterPoint 13

Energy’s facilities reflect services that are approximately 86 feet apart. This 14

suggests that the actual minimum system would include capacity of no more than 15

2.5 CFH. However, to err on the side of weather-sensitive (residential) 16

customers I used 5 CFH as the maximum possible overlap requiring elimination. 17

Given this adjustment, there can be no overlap between the capacity included in 18

the minimum system and the remaining capacity. 19

10 The 8.5, 4.6, and 2.5 amounts are small compared to the CFH requirements of typical residential appliances. For example, a conventional, tank-type residential gas water heater requires from 30 CFH to 50 CFH depending upon its size and space-heating equipment typically use from 30 CFH to 130 CFH. Typical residential meters are designed to measure between 175 CFH and 250 CFH.


23

Q. Please discuss the other gas plant accounts related to the central distribution 1

function. 2

A. The other gas plant accounts related to the central distribution function are as 3

follows: 4

1. Land & Land Rights, recorded in Account No. 374, which is the cost of 5

owning, leasing, or accessing the land occupied by the distribution mains 6

and other components of the common grid. 7

This investment has been classified between customer-related and 8

capacity-related based on the ratio determined for the distribution mains 9

above. 10

2. Structures & Improvements, recorded in Account No. 375, which is the 11

cost of surface structures and improvements thereto related to the 12

common grid. This investment is primarily caused by and required for the 13

support of the Company’s distribution system networks, which are 14

composed of distribution system mains. 15



above. 18

3. Measurement and Regulation Station Equipment, recorded in Account No. 19

378, which is the cost of installed meters, gauges, and other equipment 20

used in measuring and regulating gas in connection with distribution 21

system operations other than the measurement of gas deliveries to 22

customers. This account also contains investment in equipment to add 23

odorant to the natural gas stream. This investment is caused by the 24


24

requirement to measure and odorize the natural gas as well as to gauge 1

and correct pressure levels within distribution system mains. 2



above. 5

Q. Please discuss CenterPoint Energy’s gas plant related to the downstream 6

distribution function and your classification of the related Company investment. 7

A. The plant dedicated to the downstream distribution function is assigned to 8

customer classes on Exhibit (MAT-WP) Workpaper 1, page 13, and consists of: 9

1. Services, recorded in Account No. 380, which is the cost of installed 10

service pipes and accessories leading to customer premises. Completed 11

services begin with connection to a distribution system main and extend to 12

the inlet side of a customer’s meter installation, while stub services extend 13

only to the customer’s property line or curb stop. This investment is 14

caused by the requirement to connect individual customers to the common 15

distribution system networks. The cost of these service lines vary based 16

on their size and length, which has to do with maximum rate of flow. This 17

account balance is assigned to customer classes based on the 2014 18

average cost to install a service line and meter set used to serve each 19

customer class. 20

2. Meters, recorded in Account No. 381, which is the cost of meters for use 21

in measuring gas delivered to end-use customers, whether actually in 22

service or held in reserve. This investment is caused by the requirement 23


25

to measure gas deliveries on an individual customer basis. The cost of 1

individual customer meters varies based on the size of the meter in terms 2

of maximum rate of flow. This account balance is assigned to customer 3

classes based on the 2014 average cost to install a service line and meter 4

set used to serve each customer class. 5

3. Meter Installations and House Regulators, recorded in Account No. 382, 6

which is the cost of labor, material used and expenses incurred in 7

connection with the installation of small volume customer meters. This 8

investment is caused by the requirement to measure gas deliveries on an 9

individual customer basis. House regulators are devices usually installed 10

adjacent to, and just upstream of the meter. These devices reduce (and 11

maintain) meter inlet pressure levels from those required to achieve gas 12

distribution through mains and service lines to that required for final 13

measurement and end-use. 14

This account balance is assigned to customer classes based on the 2014 15

average cost to install a service line and meter set used to serve each 16

customer class. 17

4. House Regulator Installations, recorded in Account No. 384, which is the 18

cost of house regulators, whether actually in service or held in reserve, 19

and the expense incurred in connection with the original installation of 20

house regulators. This account balance is assigned to customer classes 21

based on the 2014 average cost to install a service line and meter set. 22

5. Industrial Measurement & Regulating Stations, recorded in Account No. 23

385, which is the cost of special and expensive installations of measuring 24


26

and regulating station equipment located on the distribution system 1

serving large volume industrial and commercial customers. This 2

investment is caused by the requirements to regulate pressures 3

associated with industrial deliveries. These costs are assigned exclusively 4

to large volume customers, and split between customer classes based on 5

2014 average cost. 6

6. Communication Equipment, recorded in Account No. 397.2, that contains 7

the cost of encoder-receiver transmitter (“ERT”) equipment used to gather 8

meter readings electronically. This investment has been allocated on the 9

basis of the number of ERTs installed by class. 10

Q. Please discuss CenterPoint Energy’s “auxiliary gas plant” used to some extent to 11

support one or more of the first two functions. 12

A. The plant that falls into this function is assigned to customer classes on Exhibit 13

___ (MAT-WP) Workpaper 1, page 14, and consists of: 14

1. Franchises and Consents, recorded in Account No. 302, which contains 15

amounts paid to governments (federal, state, or local) in consideration for 16

franchises, consents, or certificates with terms of more than one (1) year, 17

together with any necessary and reasonable expenses incident to 18

procuring such franchises, consents, or certificates of permission and 19

approval, including expenses of organizing and merging separate 20

corporations, if any, where statutes require, solely for the purpose of 21

acquiring franchises. 22


27

2. Miscellaneous Intangible Plant, recorded in Account No. 303, which 1

contains the cost of patent rights, licenses, privileges, and other intangible 2

property necessary or valuable in the conduct of the Company’s utility 3

operations and not chargeable to any other account. 4

3. Other Equipment, recorded in Account 386, which is the cost of all other 5

distribution system equipment not provided for in the foregoing accounts. 6

4. Structures and Improvements, recorded in Account No. 390, which 7

contains the cost of in-place structures and improvements used for utility 8

purposes, the cost of which is not properly includible in other structures 9

and improvements accounts. 10

5. Office Furniture and Equipment, recorded in Account No. 391, which 11

contains the cost of office furniture and equipment owned by the Company 12

and devoted to utility service, and not permanently attached to buildings 13

and not assigned to other plant accounts on a functional basis. 14

6. Transportation Equipment, recorded in Account No. 392, which contains 15

the cost of transportation vehicles used for utility purposes. 16

7. Tools, shop, and garage equipment, recorded in Account No. 394, which 17

contains the cost of tools, implements and equipment used in 18

construction, repair work, general shops and garages, not specifically 19

provided for or includible in other accounts. 20

8. Power Operated Equipment, recorded in Account No. 396, which contains 21

the cost of power operated equipment used in construction or repair work, 22

inclusive of tools and accessories acquired for use with such equipment 23


28

and the vehicle on which such equipment is mounted, but exclusive of 1

equipment includible in other accounts. 2

9. Communication Equipment, recorded in Account No. 397, (exclusive of 3

Account No. 397.2, ERTs, discussed above), which contains the cost of 4

installed telephone and mobile radio equipment for general use in 5

connection with the Company’s utility operations. 6

10. Miscellaneous Equipment, recorded in Account No. 398, which contains 7

the cost of equipment used and useful in the Company’s utility operations 8

but not includible in any other account. 9

These investments are required to support the central and downstream 10

distribution facilities already described. Accordingly, these account balances are 11

classified between customer costs and capacity costs in the same proportion as 12

the sum of the classified costs of the central and downstream distribution plant. 13

Q. Please discuss CenterPoint Energy’s non-distribution plant. 14

A. CenterPoint Energy has certain facilities classified as Production rather than 15

Distribution under the Uniform System of Accounts. These are storage-related 16

investments located both downstream and upstream of CenterPoint Energy’s city 17

gates. Upstream facilities are accessed through attached pipelines. These are 18

in place to support the design-day deliverability. Additionally, there are peak-19

shaving facilities, located on the distribution system to meet design-day load 20

requirements. Production plant has been assigned to the customer classes 21

based on the relative demand assessment. See Exhibit (MAT-WP) CARD 22

Workpaper 1, Page 15. 23


29

Classification-Operation & Maintenance Expense (See Exhibit (MAT-WP) CARD 1

Workpaper 1, pages 16-27) 2

Classification-Distribution Operation: 3

Q. Please discuss your classification of distribution operation expenses, including 4

any direct assignments you made. 5

A. A description of the distribution operation expense accounts and their 6

classification and assignment follows: 7

1. Operation Supervision & Engineering, recorded in Account No. 870, and 8

Maintenance Supervision & Engineering, recorded in Account No. 885, 9

contain the cost of labor and expenses incurred in the general supervision 10

and direction of distribution system operations & maintenance. 11

These expenses are classified between customer costs and capacity 12

costs in the proportions indicated for the sum of the supervised accounts, 13

which are Account Nos. 871-879, and 886-893, inclusive. 14

2. Distribution Load Dispatching, recorded in Account No. 871, contains the 15

cost of labor, materials used and expenses incurred in dispatching and 16

controlling the supply and flow of gas through the distribution system 17

networks, which consist of distribution mains. 18


costs in the same proportions determined for Account No. 376 – 20

Distribution Mains. 21


30

3. Mains & Services Expenses, recorded in Account No. 874, contains the 1

cost of labor, material used and expenses incurred in operating 2

distribution mains and services. 3


costs in the same proportion determined for the combination of Account 5

No. 376 – Distribution Mains and Account No. 380 – Services. 6

4. Measurement & Regulating Station Expense – General, recorded in 7

Account No. 875, contains the cost of labor, material used and expenses 8

incurred in operating general distribution measuring and regulating 9

stations as required to measure volumes and maintain correct pressure for 10

delivery requirements within distribution networks composed of distribution 11

mains. 12


costs in the same proportion determined for Account No. 376 – 14


5. Measurement & Regulating Station Expense – Industrial, recorded in 16


incurred in operating large measuring and regulating stations to serve 18

specific commercial and industrial customers. 19

These expenses are directly assigned to the large volume customer 20

classes. 21

6. Measurement & Regulating Station Expense – Industrial & City Gate 22

Check Stations General, recorded in Account No. 877, contains the cost of 23

labor, material used and expenses incurred in operating general 24


31

distribution measuring and regulating stations as required to measure 1

volumes and maintain correct pressure at points of entry to the central 2

distribution system. 3




7. Meter & House Regulator Expenses, recorded in Account No. 878, 7

contains the cost of labor, material used and expenses incurred in 8

connection with removing, resetting, changing, testing and servicing 9

customer meters and house regulators. 10

These expenses are assigned to customer classes, and then subdivided 11

between customer costs and capacity costs on the same basis as the 12

underlying investment in surface-level (above-ground) downstream plant. 13

Surface-level downstream plant includes Account Nos. 381 – Meters, 382 14

– Meter Installations, and 383 – House Regulators. In other words, these 15

accounts include downstream surface distribution plant excluding service 16

lines, which are below ground. 17

8. Customer Installation Expense, recorded in Account No. 879, contains the 18

cost of labor, material used and expenses incurred in work on customer 19

premises other than expenses includible in Account 878, Meter and House 20

Regulator Expenses. 21

These expenses are classified as customer costs and assigned based on 22

customer locations. 23


32

9. Miscellaneous (Other) Expenses, recorded in Account No. 880, contains 1

the cost of distribution maps and records, distribution office expenses and 2

the cost of labor, material used and expenses incurred in distribution 3

system operations and maintenance not provided for elsewhere. 4


costs in the proportions indicated for the sum of the direct operating 6

expense (supervised) accounts, which are Accounts Nos. 871-879 and 7

886-893 inclusive. 8

10. Rents, recorded in Account No. 881, contains rents for property of others 9

used, occupied or operated in connection with the operation of the 10

distribution system. 11


costs in the proportions indicated for the sum of the direct operating 13

expense (supervised) accounts, which are Accounts Nos. 871-879 and 14

886-893, inclusive. 15

Classification-Distribution Maintenance: 16

Q. Please discuss your classification of distribution maintenance expenses, 17

including any direct assignments you made. 18

A. A description of the distribution maintenance expenses and their classification 19

and assignment follows: 20

1. Structures and Improvements, recorded in Account No. 886, contains the 21

cost of labor, material used and expenses incurred in the maintenance of 22


33

structures, the book cost of which is includible in Account No. 375 – 1

Structures and Improvements. 2


costs in the same proportions determined for the underlying capital 4

investment recorded in Account No. 375 – Structures and Improvements, 5

which was drawn from the classification of Account No. 376 – Distribution 6

Mains. 7

2. Mains, recorded in Account No. 887, contains the cost of labor material 8

used and expenses incurred in the maintenance of distribution mains, the 9

book cost of which is includible in Account No. 376 – Distribution Mains. 10




3. Measurement & Regulating Station – General, recorded in Account No. 14

889, contains the cost of labor, material used and expenses incurred in 15

the maintenance of equipment, the book cost of which is includible in 16

Account No. 378, Measuring and Regulating Station Equipment – 17

General. 18


costs in the same proportions determined for the underlying capital 20

investment recorded in Account No. 378 – Measurement and Regulating 21

Station Equipment, which was drawn from the classification of Account 22

No. 376 – Distribution Mains. 23


34

4. Measurement & Regulating Station – Industrial, recorded in Account No. 1

890, contains the cost of labor, material used and expenses incurred in 2

the maintenance of equipment, the book cost of which is includible in 3

Account No. 385 – Industrial Measuring and Regulating Station 4

Equipment. This activity is required to measure volumes and regulate 5

pressures associated with large commercial and industrial deliveries. 6

The expenses, if any, are classified between customer costs and capacity 7



5. Measurement & Regulating – City Gate Check Stations, recorded in 10


incurred in the maintenance of city gate equipment. 12

The expenses, if any, are classified between customer costs and capacity 13



6. Services, recorded in Account No. 892, contains the cost of labor, material 16

used and expenses incurred in the maintenance of services, the book cost 17

of which is includible in Account No. 380 – Services. 18



underlying investment in Account No. 380 – Services. 21

7. Meter & House Regulating Expenses, recorded in Account No. 893, 22

contains the cost of labor, material used and expenses incurred in the 23

maintenance of meters and house regulators, the book cost of which is 24


35

includible in Account No. 381 – Meters and Account No. 383 – house 1

Regulators. 2



underlying investment in surface-level (above ground) downstream 5

distribution plant. Surface-level downstream distribution plant includes 6

Account Nos. 381 – Meters, 382 – Meter Installations, and 383 – House 7

Regulators. In other words, these expenses include downstream 8

distribution plant excluding service lines that are below ground. 9

8. Other Equipment, recorded in Account No. 894, contains the cost of labor, 10

material used and expenses incurred in the maintenance of other 11

distribution system equipment not provided for elsewhere, the book cost of 12

which is includible in Account No. 386 – Other Property on Customer 13

Premises. 14


costs in the same proportion as the underlying investment, which is drawn 16

from the sum of direct distribution plant, which excludes indirect 17

distribution plant, Accounts Nos. 871-879 and 886-893 inclusive. 18

Classification-Customer Services Expense: 19

Q. Please discuss your classification of customer accounts’ expenses, including any 20

direct assignments you made. 21

A. A description of the customer accounts’ expenses and their classification and 22

assignment follows: 23


36

1. Supervision, recorded in Account No. 901, contains the cost of labor and 1

expenses incurred in the general direction and supervision of customer 2

accounting and collecting activities. 3

These expenses are classified as customer costs and assigned to 4

customer classes based on the number of customer locations within each 5

class. 6

2. Meter Reading, recorded in Account No. 902, contains the cost of labor, 7

material used and expenses incurred in reading customer meters and 8

determining consumption when performed by those engaged in reading 9

meters. 10



class. 13

3. Customer Records and Collection, recorded in Account No. 903, contains 14

the cost of labor, material used and expenses incurred in work on 15

customer application, contracts, orders, credit investigation, billing and 16

accounting, collections and complaints. 17

These expenses are classified as customer costs and have been assigned 18

to customer classes based on the investment-weighted (net plant) number 19

of customer locations within each class. This investment weighting is 20

used to reflect the fact that commercial and industrial accounts can require 21

higher levels of these services commensurate with the higher level of 22

investment required to serve these customers. 23


37

4. Uncollectible Customer Accounts, recorded in Account No. 904, contains 1

losses from uncollectible utility revenues. 2


customer classes based on the number of customer location within each 4

class. 5

5. Miscellaneous Customer Accounts, recorded in Account No. 905, contains 6

the cost of labor, material used and expenses incurred for customer 7

accounting activities not provided for elsewhere. 8


customer classes based on the number of customer location within each 10

class. 11

6. Supervision, recorded in Account No. 907, contains the cost of labor, 12

material used and expenses incurred in the general direction and 13

supervision of customer service activities, the object of which is to 14

promote safe, efficient and economical use of the utility’s services. 15



class. 18

7. Customer Assistance Expense, recorded in Account No. 908, contains the 19

cost of labor, material used and expenses incurred in providing 20

instructions or assistance to present customers, the object of which is to 21

promote safe, efficient and economical use of the company’s utility 22

service. 23


38


customer classes based on system sales or throughput without CIP 2

exempt sales. 3

8. Informational and Instructional Advertising Expenses, recorded in Account 4

No. 909, contains the cost of labor, material used and expenses incurred 5

in advertising activities that primarily convey information as to what the 6

utility urges or suggests customers should do in utilizing gas service to 7

protect health and safety, to promote environmental protection, to utilize 8

their gas equipment safely and economically, or to conserve natural gas. 9



class. 12

9. Supervision, recorded in Account No. 911, contains the cost of labor, 13

material used and expenses incurred in the general direction and 14

supervision of sales activities. 15



class. 18

10. Demonstrating and Selling Expense, recorded in Account No. 912, 19

contains the cost of labor, material used and expenses incurred in 20

promotional, demonstrating and selling activities designed to promote or 21

retain the use of utility services by present and prospective customers. 22


39



class. 3

11. Advertising Expenses, recorded in Account No. 913, contains the cost of 4

labor, material used and expenses incurred in advertising designed to 5

promote or retain the use of utility service. 6



class. 9

12. Miscellaneous Sales Expense, recorded in Account No. 916, contains the 10

cost of labor, material used and expenses incurred in connection with 11

sales promotion activities that are not includible in other sale promotion 12

expense accounts. 13



class. 16

Administrative & General Expenses: 17

Q. Please discuss your classification of administrative and general expenses, 18

including any direct assignments you made. 19

A. A description of the administrative and general expenses and their classification 20

and assignment follows: 21

The expenses numbered 1 through 8 below are classified in the same 22

proportion as the total of non-gas expenses in: (a) Distribution Expenses; 23


40

(b) Customer Accounts Expense; (c) Customer Service and Informational 1

Expenses; and (d) Sales Expenses. Items 9 – 12 are allocated as 2

described below. 3

1. Salaries, recorded in Account No. 920, contains the compensation, 4

including salaries and other consideration for services of officers, 5

executives, and other Company employees, properly chargeable to utility 6

operations and not chargeable directly to a particular operating function. 7

2. Office Supplies & Expenses, recorded in Account No. 921, contains office 8

supplies and expenses incurred in connection with the general 9

administration of the Company’s utility operations that are assignable to 10

specific administrative or general departments and are not specifically 11

provided for in the other accounts. It included the expenses of various 12

administrative and general departments, the salaries and wages of which 13

are includible in Account No. 920 – Salaries. 14

3. Administrative Expense Transferred – Credit, recorded in Account No. 15

922, contains credits for administrative expenses recorded in Account No. 16

920 and Account No. 921, which are transferred non-utility or sister 17

Company operations. 18

4. Outside Services Employed, recorded in Account No. 923, contains the 19

fees and expenses of professional consultants and others for general 20

services that are not applicable to a particular operating function or to 21

other accounts, including any pay or expenses of non-employee personnel 22

engaged for special, temporary administrative or general purposes. 23


41

5. Injuries & Damages, recorded in Account No. 925, contains the cost of 1

insurance, or insurance reserves, and the cost of labor and related 2

supplies incurred in related activities to protect the Company against 3

injuries or damage claims of employees or others. 4

6. Pensions & Benefits, recorded in Account No. 926, contains pensions paid 5

to or on behalf of retired employees as well as cost incurred for related 6

activities. 7

7. Miscellaneous General Expenses - Corporate, recorded in Account Nos. 8

930.2 and 930.4, contains the cost of labor and expenses incurred in 9

connection with the general management of the utility. 10

8. Rents, recorded in Account No. 931, contains rents, properly includible in 11

utility operating expenses, for the property of others used, occupied, or 12

operated in connection with the customer accounts, customer service and 13

informational, sales, and general and administrative functions of the 14

Company. 15

9. Property Insurance, recorded in Account No. 924, contains the cost of 16

insurance, or insurance reserves, and the cost of labor and related 17

supplies incurred in related activities, to protect against losses and 18

damages to owned or leased property used in utility operations. 19


costs in the same proportion as the sum of gross distribution plant 21

determined above. 22


42

10. Regulatory Commission Expense, recorded in account No. 928, contains 1

all expenses incurred in connection with formal regulatory commissions or 2

other regulatory bodies. 3



class. 6

11. General Advertising Expense, recorded in Account No. 930.0, contains the 7

cost of labor, materials used and expenses incurred in advertising and 8

related activities, the cost of which by their content and purpose are not 9

provided for elsewhere. 10



class. 13

12. General Plant Maintenance, recorded in Account No. 932, contains the 14

costs assignable to customer accounts, sales and administrative and 15

general functions of labor, materials used and expenses incurred in the 16

maintenance of property, the book cost of which is includible in Account 17

No. 390 – Structures and Improvements, Account No. 391 – Office 18

Furniture and Equipment, Account No. 397, Communication Equipment 19

and Accounts No. 398 – Miscellaneous Equipment. 20

These expenses are classified in the same proportion as the auxiliary 21

distribution plant. 22

Classification-Production and Supply Expenses: 23


43

Q. Please discuss your classification of production and supply-related expenses. 1

A. I have classified production and supply-related expenses as capacity costs and 2

allocated these expenses to customer classes based on the relative demand 3

assessment. These include the Production Expenses recorded in FERC Account 4

Nos. 710-736, Other Gas Supply Expense recorded in FERC Account Nos. 813-5

843, and Production Maintenance Expense recorded in Account Nos. 740-742. 6

Classification-Taxes Other Than Income: 7

Q. Please discuss your classification of taxes other than income, including any 8

direct assignments you made. 9

A. Taxes Other Than Income, as recorded in Account No. 408, contains taxes 10

assessed by governmental authorities except income taxes. The Company has 11

excluded the taxes on revenues recorded in this account from the cost of service 12

because such taxes are not recovered through the Company’s base distribution 13

rates. Certain taxes are payroll related and are classified based in the same 14

proportion determined for overall operating expenses. The remaining taxes are 15

primarily based on property owned. These taxes are classified between 16

customer costs and capacity costs in the same proportion as the sum of gross 17

distribution net plant determined above (see Exhibit (MAT-WP) CARD 18

Workpaper 1, page 31). 19

Classification-Revenue Credits: 20

Q. Please discuss your classification of revenue credits including any direct 21

assignments you made. 22


44

A. The revenue credits are classified and directly assigned on Exhibit (MAT-WP) 1

CARD Workpaper 1, page 36 as follows: 2

1. Late Payment Charges, recorded in Account No. 487, contains late 3

payment charges assessed on bills when payment was not received by 4

the specified date due. 5

These revenues are classified as Revenue Costs (Credits) 6

2. Revenues Credited to Expenses, recorded in Account No. 489, contains 7

revenues for the shipment of the gas of others through the Company’s 8

distribution system facilities. 9

These revenues are classified as Revenue Costs (Credits). 10

3. Other Revenues, recorded in Account No. 495, contains utility revenues 11

not provided for elsewhere. 12

These revenues are classified as Revenue Costs (Credits). 13

Q. Please discuss the Relative Demand Assessment allocation methodology 14

previously approved by the Commission. 15

A. CenterPoint Energy uses a “hybrid” allocation methodology called the Relative 16

Demand Assessment to allocate capacity costs. This hybrid allocator assumes 17

the Company’s design day demand for the firm customer classes and an average 18

daily use for the dual fuel classes. Average daily use was chosen to represent 19

capacity for the dual fuel customers because the assumption is that each day, 20

CenterPoint Energy can elect to serve or to curtail those customers and thus the 21

customer’s demand on an “average” day is a fair allocation of capacity costs. An 22

adjustment has been made to the Relative Demand Assessment to reflect the 23


45

fact that CenterPoint Energy now serves firm transport customers. The updated 1

allocator assigns firm transport customers, capacity costs on the basis of their 2

average day in their peak usage month. This methodology remains consistent 3

with the previous Relative Demand Assessment, while recognizing the firm 4

nature of the new customers, and was utilized in the Company’s previous rate 5

case. 6

III.B. INDIVIDUAL CURTAILMENT AND COMPETITIVE CIRCUMSTANCES 7

(“ICCC”) CUSTOMERS 8

Q. Did the Commission order the Company to address the allocation of capacity-9

related costs to ICCC customers in its next rate case? 10

A. Yes. In its June 9, 2014, Order in Docket G-008/GR-13-316, Finding 25 states 11

that the Company shall address in detail the reasonableness of allocating 12

capacity-related costs to ICCC customers along with a discussion of each 13

capacity-related cost that is avoided due to the ICCC customers taking 14

interruptible service and each capacity-related cost that would be incurred if an 15

ICCC customer switched to firm service. 16

Q. How are capacity-related costs allocated by CenterPoint Energy to Dual Fuel 17

customers? 18

A. CenterPoint Energy has capacity-related costs in two types of expenses billed to 19

end-use customers: Distribution expenses for services provided on its own 20

delivery system, and upstream gas-cost expenses provided by interstate 21

pipelines or other service providers required to provide firm utility service. 22


46

Q. Please discuss distribution capacity costs. 1

A. As noted earlier in my testimony, the Company uses a “Relative Demand 2

Assessment” allocation, which assigns utility, non-gas capacity costs to dual fuel 3

customer classes based on their average daily use because the assumption is 4

that each day the Company can elect to serve or to curtail the dual fuel 5

customers based upon the need to first serve all firm-service customers. This 6

includes charges for mains, service lines, meters, related O&M, tax, and 7

depreciation expenses. 8

Q. Please discuss upstream gas-costs. 9

A. Dual fuel customers are not assigned direct pipeline capacity (demand) charges 10

for its Northern Natural Gas and Viking Pipeline entitlements in its Purchased 11

Gas Adjustment. However, in recent Commission decisions related to gas costs 12

in the Annual Automatic Adjustment (“AAA”) dockets, the Commission has 13

ordered that some pipeline ancillary services that the Company traditionally 14

included in its Demand Entitlement filing as Firm only expenses (demand 15

charges), instead be charged as commodity-costs so that all classes would 16

contribute toward cost recovery since it was likely that all classes benefited from 17

use of the services. These included System Management Service (“SMS”), 18

portions of seasonal reservation costs and some storage-related service costs. 19

In addition, the Company allocates a portion of its NGPL storage costs directly to 20

the Small Volume Dual Fuel customers in the winter months as a commodity cost 21


47

addition. In the last few winters this has added $0.16 - $0.48 per dekatherm to 1

the commodity cost paid by Small Volume Dual Fuel customers. 2

Q. What is an ICCC customer? 3

A. The individual ICCC customers are a subset of CenterPoint Energy’s Dual Fuel 4

rate classes. CenterPoint Energy’s market rate service rider (Section V, Page 5

11) allows it to charge market rates that are either lower or higher than standard 6

rates to customers under certain circumstances. The ICCC customer have 7

requested to pay a higher than standard delivery rate under the rider. 8

CenterPoint Energy’s policy is to curtail Dual Fuel customers based upon their 9

delivery margin rate. The ICCC customer have requested to pay a higher 10

delivery margin rate to reduce the amount of potential curtailment they might 11

experience. 12

Q. Does CenterPoint Energy ever interrupt Dual Fuel and ICCC customers? 13

A. Yes. While the Company is able to serve all of its customers for most days of the 14

year, under weather extremes the Company must curtail Dual Fuel customers in 15

order to provide the supply and capacity contracted for its firm customers’ use. 16

These curtailments can range from just a few customers on an isolated 17

branchline up to a full Dual Fuel customer curtailment depending on the 18

conditions. 19

As an example, CenterPoint Energy curtailed all of its Dual Fuel customers, 20

including ICCC customers, on January 5-7, 2014, during a particularly cold 21

period, and had a few additional partial curtailments in late January 2014 and 22


48

early March 2014. Curtailments were required both due to supply and capacity 1

availability. CenterPoint Energy also called partial curtailments in the 2014/2015 2

heating season. 3

As explained in other dockets before the Commission, when it interrupts Dual 4

Fuel customers due to a shortage of contracted gas supply or pipeline capacity, 5

customers have the option to either discontinue use of natural gas or purchase 6

their own natural gas supplies and transport the gas during periods of 7

curtailment. The customer, in that event, is changed to a Transportation 8

customer and continues to use natural gas for which they are billed delivery 9

charges, plus the transportation premium ($100 per month) on their basic charge. 10

Q. Are the capacity related costs assigned to the Dual Fuel customers, including 11

ICCC customers, reasonable? 12

A. Yes. Similar to all natural gas utilities, CenterPoint Energy has essentially two 13

primary types of “capacity-related costs.” The Company has distribution system 14

capacity-related costs which cover the costs that it incurs in constructing its 15

distribution system to deliver natural gas from its town border stations to the 16

customers’ meters, and the Company has interstate pipeline capacity-related 17

costs which cover payments to interstate pipelines to deliver natural gas from 18

production areas to the Company’s town border stations.. 19

The ICCC customers are a subset of CenterPoint Energy’s Small Volume Dual 20

Fuel (“SVDF”) rate class. CenterPoint Energy does not purchase interstate 21

pipeline capacity to serve interruptible customers (including ICCC customers) 22


49

and also does not include interruptible customers (including ICCC customers) 1

when constructing the firm requirements of its distribution system. 2

It is reasonable to not allocate additional interstate pipeline capacity costs to the 3

ICCC customers (other than what is already being allocated to the SVDF class, 4

as described above) as they are interruptible customers that can be curtailed in 5

the event that the Company does not have enough pipeline capacity or 6

commodity supply under contract to serve them on any given day. Since 7

CenterPoint Energy procures no pipeline capacity to serve these customers, no 8

additional interstate pipeline capacity-related costs should be allocated to them. 9

It is also reasonable to not allocate additional distribution system capacity-related 10

costs to the ICCC customers because Interruptible customers are already 11

allocated a portion of the Company’s distribution system costs in the class cost of 12

service study based upon the class’ average daily use, as described previously. 13

That allocation already fairly recovers the distribution system costs from 14

interruptible customers and no further allocation for ICCC customers is 15

warranted. 16

Q. What capacity-related costs are avoided by the ICCC customers taking 17

interruptible service? 18

A. CenterPoint Energy avoids all interstate pipeline capacity costs for dual fuel sales 19

and transportation service customers, as the Company does not purchase any 20

such capacity to serve them. These interstate pipeline capacity costs are 21

charged to firm customers as demand costs in the Purchased Gas Adjustment. 22


50

As noted earlier, some ancillary pipeline service costs are currently billed as 1

commodity gas costs to dual fuel customers. 2

It is also possible that CenterPoint Energy has avoided some distribution system 3

capacity-related costs related to serving Dual Fuel sales and Transportation 4

customers. On a forward-looking basis, CenterPoint Energy may avoid some 5

distribution capacity expansion costs, as it does not plan for the dual fuel loads 6

during peak system usage. 7

Q. What capacity-related costs would be incurred if an ICCC customer switched to 8

firm service? 9

A. First, CenterPoint Energy would need to secure firm pipeline entitlement and any 10

ancillary pipeline services required to provide firm service. These costs are 11

generally charged through the gas-cost portion of the bill, and would be roughly 12

equivalent to the current demand charges for firm customers. 13

If the Company were to have large numbers of Dual Fuel customers switch to 14

firm service, the current average per-unit costs for demand service could be 15

expected to increase. CenterPoint Energy’s demand portfolio has grown over 16

the years and due to competitive negotiations includes discounts on vintage units 17

of demand entitlement. If additional pipeline entitlement units were required to 18

offer firm service to current Dual Fuel customers, the costs charged by the 19

pipelines(s) would be expected to vary depending upon the pipeline that serves 20

the customer, where they are located on the Company’s distribution system, if 21

pipeline construction is required, and whether the additional charges will be 22

borne directly by the customer or spread over all of the existing firm customers. 23


51

An additional unit of entitlement on Viking could be $57 per year and on NNG at 1

current full rates could be as much as $116 per year. 2

In addition to the incremental pipeline service required, CenterPoint Energy 3

would need to determine whether its existing distribution system is capable of 4

serving the customer’s usage on a firm basis or whether a distribution system 5

upgrade would be required. The costs would vary on a case-by-case basis, and 6

could be minimal for customers on parts of the system with available distribution 7

capacity, but could be very expensive if located in an area of capacity constraint. 8

Costs, if any, could be charged directly to the customer under certain 9

circumstances, or may be justified to assign to the firm class as a whole under 10

current tariffs. 11

Additionally, customers switching from Dual Fuel to firm service would no longer 12

need telemetry equipment, so the cost of the more expensive meter and the 13

O&M expense related to daily meter reading would be eliminated, partially 14

replaced with the cost of monthly reading. 15

III.C. MINIMUM SYSTEM STUDY 16

Q. Has the Company prepared multiple minimum system studies? 17

A. Yes. In the previous rate case the Company was ordered to prepare minimum 18

system studies that reflect a 2-inch pipe, 1-inch pipe, and zero-inch pipe 19

minimum system. 20

Q. What is your recommendation regarding the appropriate minimum system study? 21


52

A. Consistent with the previous discussion that begins on page 15 of this testimony, 1

I recommend the adoption of the 2-inch pipe minimum system study presented in 2

the CARD model in Workpaper 1. This methodology is consistent with the 3

Company’s practice in all other jurisdictions and appropriately reflects the 4

minimum system, as more fully discussed above. 5

Q. Has this methodology been adopted by all of the CenterPoint Energy 6

jurisdictions? 7

A. The 2-inch pipe minimum system is the methodology upon which rates have 8

been set in 14 of the 15 non-Minnesota CenterPoint Energy jurisdictions. 9

Q. What is the other jurisdiction and what methodology did it employ? 10

A. In Arkansas, for CenterPoint Energy, the Arkansas Commission previously 11

adopted an Arkansas Commission Staff position that recommended a 1-inch pipe 12

minimum system, however this is not currently the position supported by the 13

Arkansas Commission Staff. 14

Q. Please elaborate. 15

A. The Arkansas Commission Staff no longer supports the 1-inch pipe minimum 16

system as advanced by the Arkansas Commission Staff in the previous 17

CenterPoint Energy rate case. In fact, the Arkansas Commission Staff worked 18

with the utilities and other consumer groups and passed House Bill 1655,11 which 19

11 An Act To Reform Rate Making Of Public Utilities; To Declare An Emergency: And For Other Purposes, State of Arkansas, 90th General Assembly, Regular Session, 2015


53

dictates that the minimum system reflect the predominant installed size main that 1

is at least 2-inches in diameter.12 Thus when the Company files its next rate 2

case in Arkansas under this legislation, the Arkansas Commission will adopt the 3

2-inch pipe minimum system methodology and make Arkansas consistent with 4

the other CenterPoint Energy jurisdictions. 5

Q. Is the 2-inch pipe minimum system methodology consistently approved by 6

CenterPoint Energy’s non-Minnesota jurisdictions? 7

A. Yes. In fact, one Commission recently precluded the issue from even being 8

litigated because they had “never” reached any other conclusion than that the 2-9

inch minimum system is the appropriate methodology for determining the split 10

between customer and capacity costs.13 11

Q. What are the results of the three minimum system studies? 12

A. The chart below shows the resulting customer and capacity allocation 13

percentages that result from the three minimum system studies. 14

1-inch 2-inch zero-inch

Customer % 20.8 48.5 53.5

Capacity % 79.2 51.5 46.5

Q. Why do you not recommend the 1-inch minimum system study? 15

12 Section 2, Arkansas Code Title 23-4-422(b)(3)(B)(ii), as amended by House Bill 1655. 13 Railroad Commission of Texas, Interim Order, Docket No. GUD 9869, July 14, 2009, and Commission Conference Transcript, Docket No. GUD 9791, October 7, 2008, page 38, lines 5-23.


54

A. 1-inch pipe is simply not representative of the Company’s mains in Minnesota, 1

and thus does not conform with the constraints discussed previously. A 2

minimum system study needs to determine the appropriate split between 3

customer and capacity costs by determining the proportion of a minimum system 4

that is related to the costs of offering a customer the option of taking service, 5

even when no gas is consumed. While a minimum system is a theoretical 6

construct and does not exist, there should be some attempt to mimic the 7

engineering and operational realities of the utility’s system (real-world distribution 8

pipe in the ground) and for this reason the NARUC Electric Cost Allocation 9

Manual, on page 95, introduces the concept of applying constraints to the 10

selection of the minimum system. These constraints are discussed earlier in my 11

testimony and clearly point to 2-inch pipe as being consistent with NARUC’s 12

guidance, the Company’s actual utility system, and its methodology across all of 13

its jurisdictions. 14

Q. Why do you not recommend the zero-inch minimum system study? 15

A. The zero-inch minimum system study is a hypothetical construct that is not 16

appropriate for the Company based upon the results derived by Company 17

Witness Mr. Russell Feingold, as described in his Direct Testimony. It is my 18

understanding that Mr. Feingold concluded, based upon a series of statistical 19

analyses, that the zero-intercept method (upon which the zero-inch minimum 20

system study is based) yields unacceptable results and thus should not be used 21

by CenterPoint Energy to determine its customer component of distribution mains 22

to allocate the cost of distribution mains in its CCOS study. 23


55

IV. SUMMARY AND CONCLUSION 1

Q. Please summarize your testimony. 2

A. My testimony supports the required CCOS study, the CARD model. The CARD 3

models supplied by the Company as Workpaper 1, Workpaper 6, Workpaper 7, 4

and Workpaper 8 are compliant with Statute, Law, and the previous Commission 5

Order. Workpaper 1 represents my recommended CARD model, which reflects 6

income taxes allocated by a taxable income methodology previously accepted by 7

the Commission and utilizes the 2-inch minimum system study. My testimony 8

includes: a technical appendix and Workpaper 2, which detail and discuss the 9

FERC Accounts and the allocation methodologies utilized by the Company; a 10

discussion of the minimum system analysis; and, as required by previous 11

Commission Order, a discussion of the appropriateness of the allocation of costs 12

to ICCC customers. 13

Q. Does this conclude your direct testimony? 14

A. Yes, it does. 15

MR. MATTHEW A. TROXLE Docket No. G-008/GR-15-424

SCHEDULE TABLE OF CONTENTS

I. Schedule 1 – Professional Experience

II. Schedule 2 – Pro Forma Statement of Income

Docket No. G-008/GR-15-424 Exhibit (MAT-D)

Schedule 1, Page 1 of 4

MATTHEW A. TROXLE Director of Rates, Rates & Regulatory Research

CenterPoint Energy Service Company, LLC 1111 Louisiana Street, Houston, Texas 77002

CURRENT RESPONSIBILITIES (2012 – Present) Overall responsibilities include directing the development and implementation of strategy around cost of service, revenue requirements, cost allocation, rate design, and tariffs for delivery rates in many jurisdictions across six different states. Ensures compliance with regulatory requirements and coordinates with many departments, the development and implementation of risk mitigation strategies for changes in revenues and costs. This includes review, analysis, and participation in the formulation of law, rules, and policy at the state and federal level. PREVIOUS PROFESSIONAL EMPLOYMENT CenterPoint Energy Service Company, LLC – 2008 – Present Manager of Rates 2008-2012 Public Utility Commission of Texas – 1999 – Dec. 2007 Director, Tariff and Rate Analysis 2007 Director, Retail Market Oversight 2005-2007 Senior Rate Analyst, Retail Market Oversight 2000-2005 Rate Analyst, Costing & Pricing 1999-2000 Louisiana Public Service Commission – 1997 – 1999 Economist, Economics & Rate Analysis Division 1997-1999 EDUCATION Louisiana State University, B.S., Business Administration/Pre-Law, 1995 Louisiana State University, M.S., Economics, 1997 PREVIOUS TESTIMONY Arkansas Public Service Commission: Docket No. 10-010-U – In the Matter of a Notice of Inquiry Into Energy Efficiency – March 2010, Rebuttal – April 2010. Docket No. 07-081-TF – In the Matter of the Application of CenterPoint Energy Arkansas Gas For Approval of its “Quick Start” Energy Efficiency Program, Portfolio and Plan Including Its Cost Recovery Rider – July 2009, Rebuttal – September 2009, Surrebuttal – October 2009. Public Utilities Commission of the State of Minnesota: Docket No. G-008/GR-13-316 – In the Matter of the Application of CenterPoint Energy Resources Corp., d/b/a CenterPoint Energy Minnesota Gas For Authority to Increase Rates for Natural Gas Utility Service in Minnesota – August 2013, Rebuttal – December 2013. Docket No. G-008/GR-08-1075 – In the Matter of the Application of CenterPoint Energy Resources Corp., d/b/a CenterPoint Energy Minnesota Gas For Authority to Increase Rates for Natural Gas Utility Service in Minnesota – November 2008, Rebuttal – July 2009.



Public Utility Commission of Texas: Docket No. 44572 – Application Of CenterPoint Energy Houston Electric, LLC For Approval Of A Distribution Cost Recovery Factor Pursuant To P.U.C. Substantive Rule 25.243 – April 2015, Rebuttal – June 2015, Settlement – June 2015. Docket No. 42111 – Complaint Of Nawaid Isa Against Ambit Energy And CenterPoint Energy Houston Electric, LLC – April 2015. Docket No. 41906 – Compliance Filing Of CenterPoint Energy Houston Electric, LLC For Approval Of A Revised Tariff For Retail Delivery Service In Compliance With New Substantive Rule 25.133 And Revised Substantive Rule 25.214 – September 2013, Settlement – April 2014. Docket No. 41540 – Application Of CenterPoint Energy Houston Electric, LLC, For Approval Of An Adjustment To Its Energy Efficiency Cost Recovery Factor – May 2013. Docket No. 40356 – Application Of CenterPoint Energy Houston Electric, LLC, For Approval Of An Adjustment To Its Energy Efficiency Cost Recovery Factor – May 2012. Docket No. 39933 – Application Of CenterPoint Energy Houston Electric, LLC, For Interim Update Of Wholesale Transmission Rate Pursuant To P.U.C. Substantive Rule §25.192(h)(1) – November 2011. Docket No. 39066 – Claims For September – December 1999 Period Severed From Docket No. 38780 (Remand Of Docket No. 20381, Proceeding To Modify ERCOT Transmission Rates For 1999 Pursuant To Subst. R. 23.67 – August 2011. Docket No. 39633 – Application Of CenterPoint Energy Houston Electric, LLC, For Interim Update Of Wholesale Transmission Rate Pursuant To P.U.C. Substantive Rule §25.192(h)(1) – August 2011. Docket No. 39363 – Application Of CenterPoint Energy Houston Electric, LLC, For Approval Of An Adjustment To Its Energy Efficiency Cost Recovery Factor – April 2011, Rebuttal – August 2011. Docket No. 38339 – Application Of CenterPoint Electric Delivery Company, LLC, For Authority To Change Rates – June 2010, Rebuttal – October 2010. Docket No. 36701 – Petition Of Texas Utility Solutions LLS For Declaratory Order Of Eligibility As A Transmission Service Customer – February 2010. Docket No. 32766 – Application Of Southwestern Public Service Company For (1) Authority To Change Rates; (2) Reconciliation Of Its Fuel Costs For 2004 And 2005; (3) Authority To Revise The Semi-Annual Formulae Originally Approved In Docket – January 2007. Docket No. 32907 – Application of Entergy Gulf States, Inc. For Determination Of Hurricane Reconstruction Costs – October 2006. Docket No. 32093 – Petition By Commission Staff For A Review Of The Rates Of CenterPoint Energy Houston Electric, LLC Pursuant To PURA §36.151 – August 2006.



Docket No. 28466 – Application of Cap Rock Energy Corporation For Electric Service Tariff – August 2005. Docket No. 30216 – Notice Of Violation By Cap Rock Energy Of PURA Section 36.004(a) Relating To Equality Of Service And Rates And P.U.C. Subst. R. 25.241(b) Relating To Form And Filing of Tariff – April 2005, Rebuttal – June 2005. Docket No. 30215 – Notice Of Violation By Cap Rock Energy Of P.U.C. Subst. R. 25.28(b)Relating To Bill Payments And Adjustments – April 2005, Rebuttal - June 2005. Docket No. 30706 – Application Of CenterPoint Energy Houston Electric, LLC For A Competition Transition Charge (CTC) – March 2005. Docket No. 28813 – Petition To Inquire Into The Reasonableness Of The Rates And Services Of Cap Rock Energy Corporation – September 2004. Docket No. 28840 – Application Of AEP Texas Central Company For Authority To Change Rates – February 2004. Docket No. 28980 – Petition Of CenterPoint Energy Houston Electric, LLC For Finding That The 40% Threshold Under PURA §39.202(e) Has Been Met For Small Commercial Customers – January 2004. Docket No. 28563 – Compliance Filing Of Oncor Electric Delivery Company Pursuant To Subst. R. 25.311 Regarding Competitive Meter Ownership – November 2003. Docket No. 28562 – Compliance Filing And Petition Of CenterPoint Energy Houston Electric, LLC To Provide Competitive Metering Service Credit Pursuant To PUC Subst. R. 25.311 – November 2003. Docket No. 28560 – Compliance Filing Of AEP Texas North Company To Provide Competitive Metering Credit – November 2003. Docket No. 28559 – Compliance Filing Of AEP Texas Central Company To Provide Competitive Metering Credit – November 2003. Docket No. 28556 – Texas-New Mexico Power Company’s Compliance Filing To Provide Competitive Metering Credit Pursuant To Subst. R. 25.311 – November 2003. Docket No. 28585 – Application Of TXU SESCO Energy Services Company To Increase Price To Beat Fuel Factors And Reduce Price To Beat Base Rates – October 2003 – Adopted Testimony of Brian H. Lloyd. Docket No. 25421 – Application of LCRA Transmission Services Corp. to Charge Rates for Transmission and Transformation Utility Cost of Service – October 2002. Docket No. 25429 – Appeal of Oncor From An Ordinance of the City of Allen and Request for Interim Relief – August 2002.



Docket No. 25960 – Application of Brazos Electric Power Cooperative, Inc. to Change Rates for Wholesale Transmission Service – Interim Rates Phase – August 2002. Docket No. 25874 – Application of Mutual Energy WTU, LP to Increase Price to Beat Fuel Factors – May 2002. Docket No. 24449 – Application of Southwestern Electric Power Company to Implement the Fuel Factor Component of Price to Beat Rates – October 2001. Docket No. 24336 – Application of Entergy Gulf States, Inc. for Approval of Price to Beat Fuel Factor – September 2001. Docket No. 24194 – Application of Texas-New Mexico Power Company to Establish Price to Beat Fuel Factor – August 2001. Docket No. 24040 – Application of TXU Electric Company to Implement Price to Beat Fuel Factors – August 2001. Docket No. 23950 – Petition of Reliant Energy, Inc. to Establish Price to Beat Fuel Factor and Request for Good Cause Exception to Subst. R. 25.41 – July 2001. Docket No. 22351 – Application of Southwestern Public Service for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule §25.344 – February 2001. Docket No. 22350 – Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule §25.344 – February 2001. Docket No. 22356 – Application of Entergy Gulf States Inc. for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule §25.344 – January 2001. Docket No. 22355 – Application of Reliant Energy Incorporated for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule §25.344 – December 2000. Docket No. 22350 – Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule §25.344 – November 2000. Docket No. 22349 – Application of Texas-New Mexico Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule §25.344 – ECOM Phase – September 2000. Railroad Commission of Texas: Docket No. 9902 – Statement of Intent of CenterPoint Energy Resources Corp., D/B/A CenterPoint Energy Entex and CenterPoint Energy Texas Gas To Increase Rates On a Division Wide Basis In the Houston Division – July 2009, Rebuttal – October 2009.

CenterPoint Energy - Minnesota Gas Docket No. G-008/GR-15-424 - Test Year Ending September 2016

Pro Forma Statement of Income, Test Year, As Adjusted for Proposed Rates

Column (A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M)

Line

No. Particulars TotalResidential Sales

ServiceA - Sales Service

B - Sales Service C - Sales Service

Large Firm Sales + Transport

Sm Vol Dual Fuel - A - Sales Service

Sm Vol Dual Fuel - B - Sales Service

Lg Dual Fuel Sales Service

Sm Vol Dual Fuel - A - Transport

Sm Vol Dual Fuel - B - Transport

Lg Dual Fuel Transport

1 Operating Revenues2 Recovery of Purchased Gas Cost 509,746,332$ 298,385,114$ 9,442,191$ 24,774,286$ 119,652,818$ 143,016$ 26,975,017$ 15,988,921$ 14,384,969$ -$ -$ -$ 3 Base Rate Revenues as Proposed 391,215,573 268,682,049 11,532,853 15,609,911 50,788,013 9,858,047 9,807,561 5,170,290 2,986,205 1,926,626 1,814,310 13,039,709 4 Total Gas Sales Revenue 900,961,905 567,067,163 20,975,044 40,384,197 170,440,831 10,001,063 36,782,578 21,159,211 17,371,174 1,926,626 1,814,310 13,039,709 5 Other Operating Revenues as Proposed 4,324,822 3,121,912 161,693 172,133 489,197 78,982 55,911 24,666 42,077 8,723 8,150 161,378 6 Total Operating Revenues 905,286,727 570,189,075 21,136,737 40,556,330 170,930,028 10,080,045 36,838,489 21,183,877 17,413,251 1,935,348 1,822,460 13,201,087 7 Operating Revenue Deductions8 Gas Purchases 509,746,332 298,385,114 9,442,191 24,774,286 119,652,818 143,016 26,975,017 15,988,921 14,384,969 - - - 9 Operating & Maintenance Expense 180,044,554 129,846,432 6,323,082 6,939,370 20,427,825 2,833,110 2,819,278 1,367,724 1,615,516 463,729 458,850 6,949,637

10 Total Operating Expense 689,790,886 428,231,546 15,765,273 31,713,656 140,080,643 2,976,126 29,794,295 17,356,645 16,000,485 463,729 458,850 6,949,637 11 Depreciation 73,053,118 53,545,654 3,164,930 3,041,721 7,866,787 1,270,766 757,597 252,855 689,623 102,513 78,969 2,281,702 12 Taxes Other Than Income 34,415,362 24,812,549 1,293,001 1,382,796 3,883,602 739,777 353,728 141,850 384,347 52,449 46,068 1,325,194 13 Total Operating Revenue Deductions 797,259,366 506,589,749 20,223,204 36,138,173 151,831,032 4,986,670 30,905,620 17,751,351 17,074,455 618,691 583,888 10,556,533 14 Operating Income 108,027,361 63,599,326 913,533 4,418,157 19,098,996 5,093,375 5,932,869 3,432,527 338,796 1,316,657 1,238,572 2,644,554 15 Federal & State Income Taxes 35,549,924 25,337,956 1,313,558 1,453,908 4,189,658 848,892 354,793 142,607 398,744 52,670 46,335 1,410,804 16 Net Operating Income 72,477,437 38,261,370 (400,024) 2,964,249 14,909,339 4,244,483 5,578,076 3,289,919 (59,948) 1,263,987 1,192,237 1,233,750 17 Overall Return 7.94% 5.88% -1.19% 7.94% 13.86% 19.47% 61.23% 89.85% -0.59% 93.46% 100.21% 3.41%

18 Interest Expense 22,272,790$ 15,874,773$ 822,972$ 910,904$ 2,624,910$ 531,849$ 222,285$ 89,347$ 249,822$ 32,999$ 29,030$ 883,899$

19 Net Income available to Common 50,204,647 22,386,597 (1,222,996) 2,053,345 12,284,428 3,712,634 5,355,790 3,200,573 (309,769) 1,230,987 1,163,207 349,851

20 Rate Base 912,819,267$ 650,605,452$ 33,728,360$ 37,332,146$ 107,578,294$ 21,797,089$ 9,110,055$ 3,661,748$ 10,238,591$ 1,352,423$ 1,189,739$ 36,225,369$ 21 % Common Equity 53.4% 53.4% 53.4% 53.4% 53.4% 53.4% 53.4% 53.4% 53.4% 53.4% 53.4% 53.4%22 Amount of Common Equity 487,719,334$ 347,618,493$ 18,021,063$ 19,946,566$ 57,479,083$ 11,646,185$ 4,867,502$ 1,956,472$ 5,470,479$ 722,600$ 635,677$ 19,355,215$ 23 Return on Common Equity 10.29% 6.44% -6.79% 10.29% 21.37% 31.88% 110.03% 163.59% -5.66% 170.36% 182.99% 1.81%

Firm Commercial/Industrial

Docket No. G-008/GR-15-424 Exhibit___(MAT-D), Schedule 2


Pro Forma Statement of Income, Test Year, As Adjusted, Pre-tariff Change


Line



B - Sales Service C - Sales Service

Large Firm Sales + Transport

Sm Vol Dual Fuel - A - Sales Service






1 Operating Revenues2 Recovery of Purchased Gas Cost 509,746,332$ 298,385,114 9,442,191 24,774,286 119,652,818 143,016 26,975,017 15,988,921 14,384,969 - - - 3 Base Rate Revenues 337,110,650$ 221,142,524 8,454,804 12,980,801 50,641,040 9,841,473 9,732,005 5,125,505 2,835,231 1,912,631 1,798,870 12,645,766

4 Total Gas Sales Revenue 846,856,982 519,527,638 17,896,995 37,755,087 170,293,858 9,984,489 36,707,022 21,114,426 17,220,200 1,912,631 1,798,870 12,645,766 5 Other Operating Revenues 4,324,822 3,121,912 161,693 172,133 489,197 78,982 55,911 24,666 42,077 8,723 8,150 161,378 6 Total Operating Revenues 851,181,804 522,649,550 18,058,688 37,927,220 170,783,055 10,063,471 36,762,933 21,139,092 17,262,277 1,921,354 1,807,020 12,807,144 7 Operating Revenue Deductions8 Gas Purchases 509,746,332 298,385,114 9,442,191 24,774,286 119,652,818 143,016 26,975,017 15,988,921 14,384,969 - - - 9 Operating & Maintenance Expense 180,044,554 129,846,432 6,323,082 6,939,370 20,427,825 2,833,110 2,819,278 1,367,724 1,615,516 463,729 458,850 6,949,637

10 Total Operating Expense 689,790,886 428,231,546 15,765,273 31,713,656 140,080,643 2,976,126 29,794,295 17,356,645 16,000,485 463,729 458,850 6,949,637 11 Depreciation 73,053,118 53,545,654 3,164,930 3,041,721 7,866,787 1,270,766 757,597 252,855 689,623 102,513 78,969 2,281,702 12 Taxes Other Than Income 34,415,362 24,812,549 1,293,001 1,382,796 3,883,602 739,777 353,728 141,850 384,347 52,449 46,068 1,325,194 13 Total Operating Revenue Deductions 797,259,366 506,589,749 20,223,204 36,138,173 151,831,032 4,986,670 30,905,620 17,751,351 17,074,455 618,691 583,888 10,556,533 14 Operating Income 53,922,438 16,059,801 (2,164,516) 1,789,047 18,952,024 5,076,801 5,857,313 3,387,741 187,822 1,302,662 1,223,132 2,250,611 15 Federal & State Income Taxes 13,165,924 9,383,919 486,476 538,455 1,551,641 314,387 131,398 52,815 147,675 19,506 17,160 522,492 16 Net Operating Income 40,756,514 6,675,882 (2,650,993) 1,250,592 17,400,383 4,762,414 5,725,915 3,334,927 40,147 1,283,156 1,205,972 1,728,119 17 Overall Return 4.46% 1.03% -7.86% 3.35% 16.17% 21.85% 62.85% 91.07% 0.39% 94.88% 101.36% 4.77%

18 Interest Expense 22,272,790$ 15,874,773$ 822,972$ 910,904$ 2,624,910$ 531,849$ 222,285$ 89,347$ 249,822$ 32,999$ 29,030$ 883,899$

19 Net Income available to Common 18,483,724$ (9,198,891)$ (3,473,965)$ 339,688$ 14,775,472$ 4,230,565$ 5,503,630$ 3,245,580$ (209,674)$ 1,250,157$ 1,176,942$ 844,220$

20 Rate Base 912,819,267$ 650,605,452$ 33,728,360$ 37,332,146$ 107,578,294$ 21,797,089$ 9,110,055$ 3,661,748$ 10,238,591$ 1,352,423$ 1,189,739$ 36,225,369$ 21 % Common Equity 53.43% 53.43% 53.43% 53.43% 53.43% 53.43% 53.43% 53.43% 53.43% 53.43% 53.43% 53.43%22 Amount of Common Equity 487,719,334$ 347,618,493$ 18,021,063$ 19,946,566$ 57,479,083$ 11,646,185$ 4,867,502$ 1,956,472$ 5,470,479$ 722,600$ 635,677$ 19,355,215$ 23 Return on Common Equity 3.79% -2.65% -19.28% 1.70% 25.71% 36.33% 113.07% 165.89% -3.83% 173.01% 185.15% 4.36%




Overall Class Cost of Service Summary


Line



B - Sales Service

C - Sales Service

Large Firm Sales +

Transport

Sm Vol Dual Fuel - A - Sales

Service

Sm Vol Dual Fuel - B - Sales

ServiceLg Dual Fuel Sales Service




1 Operating & Maintenance Expense 180,044,554$ 129,846,432$ 6,323,082$ 6,939,370$ 20,427,825$ 2,833,110$ 2,819,278$ 1,367,724$ 1,615,516$ 463,729$ 458,850$ 6,949,637$ 2 Depreciation 73,053,118 53,545,654 3,164,930 3,041,721 7,866,787 1,270,766 757,597 252,855 689,623 102,513 78,969 2,281,702 3 Taxes Other Than Income 34,415,362 24,812,549 1,293,001 1,382,796 3,883,602 739,777 353,728 141,850 384,347 52,449 46,068 1,325,194 4 Subtotal 287,513,034 208,204,635 10,781,013 11,363,887 32,178,214 4,843,654 3,930,603 1,762,430 2,689,486 618,691 583,888 10,556,533 5 Income Taxes (incl. taxes on deficiency) 35,549,924 25,337,956 1,313,558 1,453,908 4,189,658 848,892 354,793 142,607 398,744 52,670 46,335 1,410,804 6 Return on Rate Base 72,477,850 51,658,073 2,678,032 2,964,172 8,541,717 1,730,689 723,338 290,743 812,944 107,382 94,465 2,876,294 7 Total Gross Cost of Service 395,540,808 285,200,664 14,772,602 15,781,967 44,909,588 7,423,235 5,008,735 2,195,780 3,901,174 778,744 724,688 14,843,631

8 Less: Revenue Credits to the Cost of Service (under current tariff) (4,324,822) (3,121,912) (161,693) (172,133) (489,197) (78,982) (55,911) (24,666) (42,077) (8,723) (8,150) (161,378) 9 Net Cost of Service 391,215,986 282,078,751 14,610,910 15,609,834 44,420,391 7,344,253 4,952,823 2,171,114 3,859,097 770,021 716,539 14,682,254

10 Net Revenues under Current Base Rates (Incl CCRC & GAP) 337,110,650 221,142,524 8,454,804 12,980,801 50,641,040 9,841,473 9,732,005 5,125,505 2,835,231 1,912,631 1,798,870 12,645,766

11 Jurisdictional Cost-of-Service Excess (Deficiency)-Current Tariff: (54,105,336)$ (60,936,228)$ (6,156,106)$ (2,629,033)$ 6,220,649$ 2,497,220$ 4,779,181$ 2,954,391$ (1,023,866)$ 1,142,610$ 1,082,332$ (2,036,488)$




Cost of Service Model Results


Line



B - Sales Service

C - Sales Service

Large Firm Sales +

Transport

Sm Vol Dual Fuel - A - Sales

Service

Sm Vol Dual Fuel - B - Sales

ServiceLg Dual Fuel Sales Service




1 Jurisdictional Cost-of-Service Excess (Deficiency)-Current Tariff: (54,105,336)$ (60,936,228)$ (6,156,106)$ (2,629,033)$ 6,220,649$ 2,497,220$ 4,779,181$ 2,954,391$ (1,023,866)$ 1,142,610$ 1,082,332$ (2,036,488)$

2 Net Cost of Service:3 Customer 251,908,472 216,150,288 9,063,966 7,115,752 12,234,404 1,660,163 1,076,000 342,786 950,443 142,167 106,072 3,066,4324 Capacity 110,206,681 51,724,621 5,098,758 7,318,139 26,462,107 5,470,396 2,361,851 930,357 2,056,451 347,250 300,882 8,135,8685 Commodity 29,100,833 14,203,843 448,186 1,175,943 5,723,879 213,694 1,514,973 897,971 852,203 280,604 309,584 3,479,9546 Total 391,215,986 282,078,751 14,610,910 15,609,834 44,420,391 7,344,253 4,952,823 2,171,114 3,859,097 770,021 716,539 14,682,254

7 Recovery of Cost of Service:

8 Customer Costs (line 3) 251,908,472 216,150,288 9,063,966 7,115,752 12,234,404 1,660,163 1,076,000 342,786 950,443 142,167 106,072 3,066,4329 Customer Numbers 842,219 772,307 28,961 19,602 18,783 5 1,753 309 83 184 76 156

10 Monthly Basic Charge [line 8/ (line 9 x 12 months)] 24.93$ 23.32$ 26.08$ 30.25$ 54.28$ 27,669.38$ 51.15$ 92.44$ 954.26$ 64.39$ 116.31$ 1,638.05$

11 Recovery of Capacity/Commodity thru Volumetric charge:12 Capacity Costs (line 4) 110,206,681 51,724,621 5,098,758 7,318,139 26,462,107 5,470,396 2,361,851 930,357 2,056,451 347,250 300,882 8,135,86813 Commodity Cost (line 5) 29,100,833 14,203,843 448,186 1,175,943 5,723,879 213,694 1,514,973 897,971 852,203 280,604 309,584 3,479,95414 Subtotal 139,307,514 65,928,464 5,546,944 8,494,082 32,185,987 5,684,090 3,876,824 1,828,328 2,908,654 627,854 610,467 11,615,822

15 Annual Sales Volume (DT) 173,059,800 70,137,300 2,213,100 5,806,700 28,264,000 13,958,200 7,480,800 4,434,100 4,208,100 1,385,600 1,528,700 33,643,200

16 Usage Charge (line 14 / line 15) $0.80497 $0.93999 $2.50641 $1.46281 $1.13876 $0.40722 $0.51824 $0.41233 $0.69120 $0.45313 $0.39934 $0.34527



Home

Page 5


Rate Design


Line


Service A - Sales Service B - Sales Service C - Sales ServiceLarge Firm Sales +

Transport Sm Vol Dual Fuel - A - Sales Service






1 Net Revenue (Deficiency) Excess:2 Existing Excess (Deficiency) (54,105,336)$ (60,936,228)$ (6,156,106)$ (2,629,033)$ 6,220,649$ 2,497,220$ 4,779,181$ 2,954,391$ (1,023,866)$ 1,142,610$ 1,082,332$ (2,036,488)$ 3 Increase (Decrease) in Service Fees - - - - - - - - - - - - 4 Net Excess (Deficiency) (54,105,336)$ (60,936,228)$ (6,156,106)$ (2,629,033)$ 6,220,649$ 2,497,220$ 4,779,181$ 2,954,391$ (1,023,866)$ 1,142,610$ 1,082,332$ (2,036,488)$

5 Billing Determinants:6 Number of Monthly Bills per Year 10,106,632 9,267,681 347,537 235,223 225,399 60 21,032 3,711 996 2,212 909 1,872

7 Consumption Per Year 173,059,800 70,137,300 2,213,100 5,806,700 28,264,000 13,958,200 7,480,800 4,434,100 4,208,100 1,385,600 1,528,700 33,643,200

8 Present Rates:9 Customer Charge Per Month 9.50$ 15.00$ 21.00$ 43.00$ $800/$900 50.00$ 80.00$ 800.00$ 150.00$ 180.00$ 900.00$

10 Usage Charge per Mcf (incl. GAP) 1.8977 1.4648 1.3848 1.4488 0.5034 1.1409 1.0697 0.5034 1.1409 1.0697 0.5034

11 Present Rate Design Level Revenues:12 Customer Charges 112,266,165 88,042,970$ 5,213,055$ 4,939,683$ 9,692,157$ 52,800$ 1,051,600$ 296,880$ 796,800$ 331,800$ 163,620$ 1,684,800$ 13 Usage Charges 224,844,485 133,099,554 3,241,749 8,041,118 40,948,883 9,788,673 8,680,405 4,828,625 2,038,431 1,580,831 1,635,250 10,960,96614 Present Revenues * 337,110,650$ 221,142,524$ 8,454,804$ 12,980,801$ 50,641,040$ 9,841,473$ 9,732,005$ 5,125,505$ 2,835,231$ 1,912,631$ 1,798,870$ 12,645,766$

15 Proposed Rates:16 Customer Charge Per Month 11.75$ 17.25$ 26.25$ 43.00$ $800/$900 50.00$ 80.00$ 900.00$ 150.00$ 180.00$ 1,000.00$ 17 Usage Charge per Mcf (incl. GAP) 2.2782 2.5023 1.6249 1.4540 0.5632 1.1510 1.0798 0.5162 1.1510 1.0798 0.516218 New Rate Design Level Revenues:19 Customer Charges 135,428,126 108,895,252$ 5,995,013$ 6,174,604$ 9,692,157$ 58,800$ 1,051,600$ 296,880$ 896,400$ 331,800$ 163,620$ 1,872,000$ 20 Usage Charges 255,787,448 159,786,797 5,537,840 9,435,307 41,095,856 9,799,247 8,755,961 4,873,410 2,089,805 1,594,826 1,650,690 11,167,709 21 New Rate Design Revenues * 391,215,573$ 268,682,049$ 11,532,853$ 15,609,911$ 50,788,013$ 9,858,047$ 9,807,561$ 5,170,290$ 2,986,205$ 1,926,626$ 1,814,310$ 13,039,709$

22 Comparison of Base Rate Revenue Levels:23 Increase (Decrease) - Line 21 less 14 54,104,924 47,539,525 3,078,050 2,629,109 146,973 16,574 75,556 44,785 150,974 13,995 15,440 393,943

24 Excess (Deficiency) (412)$ (13,396,703)$ (3,078,056)$ 76$ 6,367,622$ 2,513,794$ 4,854,737$ 2,999,177$ (872,892)$ 1,156,604$ 1,097,772$ (1,642,545)$ * - The detailed analysis of margin for Large Firm and all dual fuel classes is considered TRADE SECRET INFORMATION and is provided in the Non-Public workpapers of Mr. Kirk Nesvig



Direct Testimony Mr. Matthew A. Troxle Before the Public ... · 9 Schedule 2. The more detailed...

Documents

Transcript of Direct Testimony Mr. Matthew A. Troxle Before the Public ... · 9 Schedule 2. The more detailed...